Mud logging depth and composition measurements

ABSTRACT

A sample that includes formation content from a subsurface formation and other sample constituents is obtained while the sample is in close proximity to the subsurface formation. While downhole, the formation content is separated from the other sample constituents by passing the sample through an oil-wet porous plate, a water-wet porous plate, or through both plates, and analyzed. Various petrophysical properties of the formation content may be determined. To further separate the formation content, one may pass the sample through a mesh, pass the sample into an expansion chamber, or draw the sample into a chamber using a moveable piston. The formation content may be analyzed downhole using, for example, a mass spectrometer, FTIR, or chromatograph. The hydrocarbon contribution from oil based drilling fluid can be accounted for. Alternatively, a capsule may be charged with “live” formation content and conveyed uphole to be analyzed.

BACKGROUND

In the petroleum industry, mud logging is a common logging technique performed at the well site as the well is being drilled. The technique uses circulating drilling fluid (mud) to carry the formation content, which is released as a result of drilling, to the surface or “uphole.” In the process of drilling a well, the drill bit uses a large force and rotary motion to break up the rock solid that constitutes the formation. In an oil bearing formation, the pores of the rock are filled with oil, water, and natural gas at reservoir (elevated) temperatures and pressures. When the rock breaks into smaller pieces, the break line passes through some pores, exposing those pores and causing their fluid content to be released. In addition, the rotary motion grounds cuttings further, causing them to have even smaller particle size (larger surface area) which also leads to more fluid being released from the remaining pores. The released fluid dissolves (mixes) in the drilling fluid (oil or water based mud) which carries those materials to the surface.

At the surface, the formation content is separated from the mud and analytical instruments are used to measure properties of interest, such as their quantity and ratio. Because in conventional mud logging the sample is brought to the surface before it is analyzed, a log operator has traditionally been able to use more sophisticated instruments and obtain more accurate data as compared to measurements made downhole. However, having the sample travel to the surface can create at least two problems: (1) a loss of depth information; and (2) an influx of contaminants. The first problem can affect the resolution of a log, while the second can cause the accuracy of a composition measurement to decrease.

SUMMARY

A sample that includes formation content from a subsurface formation and other sample constituents is obtained while the sample is in close proximity to the subsurface formation. While downhole, the formation content is separated from the other sample constituents by passing the sample through an oil-wet porous plate, a water-wet porous plate, or through both plates, and analyzed. Various petrophysical properties of the formation content may be determined. To further separate the formation content, one may pass the sample through a mesh, pass the sample into an expansion chamber, or draw the sample into a chamber using a moveable piston. The formation content may be analyzed downhole using, for example, a mass spectrometer, FTIR, or chromatograph. The hydrocarbon contribution from oil based drilling fluid can be accounted for. Alternatively, a capsule may be charged with “live” formation content and conveyed uphole to be analyzed.

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. Embodiments of determining are described with reference to the following figures. The same numbers are generally used throughout the figures to reference like features and components.

FIG. 1 illustrates a prior art well site system.

FIG. 2 shows a prior art logging tool.

FIG. 3 illustrates an example computing system usable for one or more disclosed embodiments, in accordance with the present disclosure.

FIG. 4 is a schematic drawing of a downhole sampling module, in accordance with the present disclosure.

FIG. 5 is a schematic drawing of a downhole separator, in accordance with the present disclosure.

FIG. 6 is a schematic drawing of an embodiment of a downhole separator, in accordance with the present disclosure.

FIG. 7 is a schematic drawing of a downhole sampling module in which relatively uncontaminated drilling fluid, in addition to the obtained sample, may be analyzed, in accordance with the present disclosure.

FIG. 8 is a schematic drawing showing the relative cross-sectional areas of a drill collar and a capsule, both within a wellbore and with the drill collar concentric with the wellbore, in accordance with the present disclosure.

FIG. 9 is a schematic drawing showing the relative cross-sectional areas of a drill collar and a capsule, both within a wellbore and with the drill collar eccentric to the wellbore, in accordance with the present disclosure.

FIG. 10 is a schematic drawing of a capsule, in accordance with the present disclosure.

FIG. 11 is a schematic drawing showing capsules floating on a liquid, in accordance with the present disclosure.

FIG. 12 is a schematic drawing of a capsule and a sample injection system, in accordance with the present disclosure.

FIG. 13 is a flowchart for at least one workflow embodiment, in accordance with the present disclosure.

FIG. 14 is a flowchart for at least one workflow embodiment, in accordance with the present disclosure.

FIG. 15 is a flowchart for at least one workflow embodiment, in accordance with the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

FIG. 1 illustrates a well site system in which various embodiments can be employed. The well site can be onshore or offshore. In this example system, a borehole 11 is formed in subsurface formations by rotary drilling in a manner that is well known. Some embodiments can also use directional drilling, as will be described hereinafter.

A drill string 12 is suspended within the borehole 11 and has a bottom hole assembly 100 which includes a drill bit 105 at its lower end. The surface system includes platform and derrick assembly 10 positioned over the borehole 11, the assembly 10 including a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary table 16, energized by means not shown, which engages the kelly 17 at the upper end of the drill string. The drill string 12 is suspended from a hook 18, attached to a traveling block (also not shown), through the kelly 17 and a rotary swivel 19 which permits rotation of the drill string relative to the hook. As is well known, a top drive system could also be used.

In the example of this embodiment, the surface system further includes drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19, causing the drilling fluid to flow downwardly through the drill string 12 as indicated by the directional arrow 8. The drilling fluid exits the drill string 12 via ports in the drill bit 105, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the borehole, as indicated by the directional arrows 9. In this well known manner, the drilling fluid lubricates the drill bit 105 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.

The bottom hole assembly 100 of the illustrated embodiment includes a logging-while-drilling (LWD) module 120 and a measuring-while-drilling (MWD) module 130. It may also include a roto-steerable system and motor 150 and drill bit 105.

The LWD module 120 is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g., as represented at 121. (References, throughout, to a module at the position of 120 can also mean a module at the position of 121 as well.) The LWD module includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the present embodiment, the LWD module includes a resistivity measuring device.

The MWD module 130 is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. The MWD tool further includes an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick/slip measuring device, a direction measuring device, and an inclination measuring device.

An example of a tool which can be the LWD tool 120, or can be a part of an LWD tool suite 121, is shown in FIG. 2. As seen in FIG. 2, upper and lower transmitting antennas, T₁ and T₂, have upper and lower receiving antennas, R₁ and R₂, therebetween. The antennas are formed in recesses in a modified drill collar and mounted in MC or insulating material. The phase shift of the electromagnetic wave between the receivers provides an indication of formation resistivity at a relatively shallow depth of investigation, and the attenuation of the electromagnetic wave between the receivers provides an indication of formation resistivity at a relatively deep depth of investigation. U.S. Pat. No. 4,899,112 can be referred to for further details. In operation, attenuation-representative signals and phase-representative signals are coupled to a processor, an output of which is coupleable to a telemetry circuit.

Some electromagnetic (EM) logging tools use one or more tilted or transverse antennas, with or without axial antennas. Those antennas may be transmitters or receivers. A tilted antenna is one whose dipole moment is neither parallel nor perpendicular to the longitudinal axis of the tool. A transverse antenna is one whose dipole moment is perpendicular to the longitudinal axis of the tool, and an axial antenna is one whose dipole moment is parallel to the longitudinal axis of the tool. A triaxial antenna is one in which three antennas (i.e., antenna coils) are arranged to be mutually orthogonal. Often one antenna (coil) is axial and the other two are transverse. Two antennas are said to have equal angles if their dipole moment vectors intersect the tool's longitudinal axis at the same angle. For example, two tilted antennas have the same tilt angle if their dipole moment vectors, having their tails conceptually fixed to a point on the tool's longitudinal axis, lie on the surface of a right circular cone centered on the tool's longitudinal axis and having its vertex at that reference point. Transverse antennas obviously have equal angles of 90 degrees, and that is true regardless of their azimuthal orientations relative to the tool.

Some embodiments will now be described with reference to the figures. Like elements in the various figures may be referenced with like numbers for consistency. In the following description, numerous details are set forth to provide an understanding of various embodiments and/or features. However, it will be understood by those skilled in the art that some embodiments may be practiced without many of these details and that numerous variations or modifications from the described embodiments are possible. As used herein, the terms “above” and “below,” “up” and “down,” “upper” and “lower,” “upwardly” and “downwardly,” and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe certain embodiments. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left or diagonal relationship, as appropriate. It will also be understood that, although the terms first, second, etc., may be used herein to describe various elements, these elements should not be limited by these terms. These terms are used to distinguish one element from another.

The terminology used in the description herein is for the purpose of describing particular embodiments only and is not intended to be limiting. As used in the description and the appended claims, the singular forms “a,” “an” and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will also be understood that the term “and/or” as used herein refers to and encompasses any and all possible combinations of one or more of the associated listed items. It will be further understood that the terms “includes,” “including,” “comprises,” and/or “comprising,” when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

As used herein, the term “if” may be construed to mean “when” or “upon” or “in response to determining” or “in response to detecting,” depending on the context. Similarly, the phrase “if it is determined” or “if [a stated condition or event] is detected” may be construed to mean “upon determining” or “in response to determining” or “upon detecting [the stated condition or event]” or “in response to detecting [the stated condition or event],” depending on the context.

A system and method to determine petrophysical properties of formation content released from a subsurface formation are disclosed. The disclosed system and method may be used in conjunction with a computing system as described below. In one embodiment, sampling may be done downhole at distances close to the drill bit so that depth information is more accurate. The early sampling also helps preserve the solid samples. Measuring the sample while downhole using downhole instruments ensures the results are obtained while the sample is still exposed to downhole conditions. Alternatively, the sample can be placed in special containers (capsules) and released in the upward moving mud to be carried to the surface. Once at the surface, the sample can be analyzed. Either of those two measurement approaches prevents any further contamination, and possibly wettability alteration, from earth layers above the depth of interest.

The computing system 100 shown in FIG. 3 can be an individual computer system 101A or an arrangement of distributed computer systems. The computer system 101A includes one or more analysis modules 102 that are configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein (e.g., any of the steps, methods, techniques, and/or processes, and/or combinations and/or variations and/or equivalents thereof). To perform those various tasks, analysis module 102 operates independently or in coordination with one or more processors 104 that is (or are) connected to one or more storage media 106. The processor(s) 104 is (or are) also connected to a network interface 108 to allow the computer system 101A to communicate over a data network 110 with one or more additional computer systems and/or computing systems, such as 101B, 101C, and/or 101D (note that computer systems 101B, 101C, and/or 101D may or may not share the same architecture as computer system 101A, and may be located in different physical locations, e.g., computer systems 101A and 101B may be on a ship underway on the ocean, while in communication with one or more computer systems such as 101C and/or 101D that are located in one or more data centers onshore, on other ships, and/or located in various countries on different continents).

A processor can include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.

The storage media 106 can be implemented as one or more computer-readable or machine-readable storage media. Note that while in the example embodiment of FIG. 3 storage media 106 is depicted as within computer system 101A, in some embodiments, storage media 106 may be distributed within and/or across multiple internal and/or external enclosures of computing system 101A and/or additional computing systems. Storage media 106 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices. Note that the instructions discussed above can be provided on one computer-readable or machine-readable storage medium, or alternatively, can be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture). An article or article of manufacture can refer to any manufactured single component or multiple components. The storage medium or media can be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions can be downloaded over a network for execution.

It should be appreciated that computing system 100 is only one example of a computing system, and that computing system 100 may have more or fewer components than shown, may combine additional components not depicted in the example embodiment of FIG. 3, and/or computing system 100 may have a different configuration or arrangement of the components depicted in FIG. 3. For example, though not shown explicitly, computing system 100 would generally include input and output devices such as a keyboard, a mouse, a display monitor, and a printer and/or plotter. The various components shown in FIG. 3 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.

Further, the processes in the processing methods described above may be implemented by running one or more functional modules in information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are included within the scope of this disclosure.

As alluded to above, conventional mud logging has shortcomings: most notably, the loss of accurate depth information and contamination of the sample. A crude oil sample, which is a mixture of molecules with different numbers of carbon and hydrogen atoms, travels the length of the wellbore (commonly as much as 20,000 feet) before it reaches the surface. The travel time can be as much as an hour, depending on the mud circulation rate. The hydrocarbons making up the crude oil have different viscosities and can travel at different speeds, causing the composition of the crude oil at the surface to be different from the nascent composition. In addition, as the sample travels uphole, hydrocarbons from other, shallower, formations may seep in and mix with the original mixture, causing further change to the composition. Often the samples under downhole conditions are “live,” meaning they contain dissolved gas, and while traveling uphole they encounter increasingly lower pressures that allow their volatile components to release. This effect is especially important for solid samples. Since the volatile components travel faster, it is difficult to relate the volatile part to the remainder of the sample later on at the surface. In addition, the release of the volatile components changes the solubility of some crude oil components, such as asphaltenes, for example, and may cause them to precipitate, which leads to composition error.

Inaccurate depth information is another shortcoming of conventional uphole mud logging. The depth is usually calculated based on the mud flow rate and the volume of mud in the well. This calculation assumes the samples from each depth remain intact while taking the long trip up to the surface. With turbulence normally present in the borehole as a result of a rotating drill pipe and high mud flow rate, the accuracy of the computed depth information is marginal at best.

In one embodiment of the present disclosure, the sample integrity and its depth information are retained by obtaining and analyzing a sample soon after it is released from the formation. The sampling is performed by a module positioned in the bottomhole assembly (BHA) in relatively close proximity to the drill bit. The sampling module 400, shown in FIG. 4, performs a coarse filtering to separate large solid particles (cuttings) from the mud. In this particular embodiment, the fluid enters the tool at the opening 412 and exits the tool at a somewhat higher location 414. Opening 412 is covered with a mesh structure 413 to prevent solids with sizes larger than the mesh size from entering the sampling tube 416. The fluid in sampling tube 416 comprises mud, hydrocarbon released from the formation as a result of rock being broken up and ground, and powdered rock solids too small to be rejected by the mesh structure. The hydrocarbons in the sample are separated from the mud using a separator 417. Separator 417 may be of various designs depending on whether it is gaseous or liquid hydrocarbons that are being separated. Another possible consideration when choosing a design is that, in the while-drilling environment, there may not be sufficient time to separate the oil from the water. In addition, the separation may be impeded by the constant rotation of the BHA. Note that during the drilling operation, the entire BHA is rotating, and also that the BHA can be operating vertically (vertical well), horizontally (horizontal well), or at some angle between vertical and horizontal (deviated well). Unlike in laboratory conditions in which gravity forces the more dense liquids to migrate towards a bottom and the gases to migrate towards a top, under downhole conditions the liquid and gaseous phases are continuously mixed together, making their separation a challenge.

For gaseous hydrocarbons, the separation can be achieved by directing a portion of the fluid to separator 417, wherein separator 417 has the design shown in FIG. 5. The separator 417 includes a chamber 418 for subjecting the fluid to a volume expansion that causes the sample pressure to drop. Chamber 418 is evacuated before the start of sampling. Then, with valve 424 closed, the valve 421 connecting chamber 418 to sampling tube 416 is opened, allowing liquid to enter the chamber 418. Since chamber 418 is initially under vacuum, the liquid entering the chamber will expand. Once the desired amount of liquid is collected in chamber 418, the valve 421 is closed and valve 424 opened. In this embodiment, further volume expansion may be achieved, if desired (for example, when the chamber 418 is completely filled with sample material), by having a chamber 420 evacuated using a pump 422. At the time of expansion, the evacuated chamber 420 is placed in fluid communication with sample chamber 418 by opening valve 424. The volume of the sample increases from the volume of chamber 418 [V(418)] to the combined volumes of chambers 418 and 420 [V(418)+V(420)], causing the pressure to decrease. When the pressure drops below the bubble point at the given downhole temperature, the gaseous hydrocarbon(s) (at that temperature) boil off and form a gas phase. An optional ultrasonic transducer 426 may be positioned in chamber 418 and used to agitate the liquid sample, facilitating a faster gas separation.

To separate the gas from the liquid mud, the connection between chambers 418 and 420 may be equipped with a cartridge 428 containing a selective barrier such as porous ceramic (also called a porous plate). The wettability of the porous plate is chosen to selectively block the liquid from entering chamber 420. The porous plate (oil-wet or water-wet) is commercially available. The wettability of the porous plate changes the relative permeability of the liquids, but has no significant effect on the permeability of the gaseous components. Thus, a water-wet porous plate allows only the water to pass while blocking the liquid hydrocarbons. Similarly, an oil-wet porous plate allows the liquid hydrocarbons to pass while blocking the liquid water. Both of these plates allow the gaseous hydrocarbon and water vapor to pass through. In an embodiment, the cartridge 428 may have both oil-wet and water-wet porous ceramic placed back-to-back to block both kinds of mud liquids. In yet another embodiment, as shown in FIG. 6, the pressure is reduced incrementally. A piston 419 is placed in contact with chamber 418 through an appropriate porous plate. The piston is moved gradually using a motor 429 to cause a small pressure difference and collect the gas phase. Note that the blocking effect of the porous plate works up to certain pressure difference, which places a pressure differential restriction on the two sides of cartridge 428.

We now discuss hydrocarbons that are in a liquid state under the given downhole temperatures and pressures. In one embodiment, the liquid is vaporized and the procedure in the previous section is used to separate it. That is, the pressure in chamber 418 is reduced to vaporize some portion of those hydrocarbons and separate them using the procedure described above. Although certain heavier hydrocarbons can be extracted with this approach, it is not practical to extract all of the crude oil constituents in this manner. This embodiment is useful when the lighter liquid hydrocarbons are desired.

To separate the majority of liquid hydrocarbons from the hydrocarbon/drilling fluid mixture, porous plates with different wettabilities may be used. The mud/hydrocarbon mixture of chamber 418 maybe passed through cartridge 428 using the proper choice of wettability for the porous plate. For example, if the well is drilled with water based mud, an oil-wet porous ceramic may be used in cartridge 428 to block the aqueous mud and solids from entering chamber 420. However, if the well is drilled with oil based mud (OBM), then in addition to the hydrocarbons from the formation, liquid hydrocarbons making up the OBM will be present. The OBM oil is commonly diesel oil (e.g., C14, C16). Since those components may have counterparts in the formation fluid, their presence may interfere with the measurement of those counterpart components.

Consider the case in which the fluid in chamber 418 comprises OBM hydrocarbons, formation hydrocarbons, cutting fine solids, water from the formation, and water from the OBM. If the solution is directed to pass through cartridge 428, which contains an oil-wet porous plate, the water and solid constituents will be blocked, but the OBM hydrocarbons will pass along with the formation hydrocarbons. The sample thus obtained may be analyzed (as described below), but the measurement is made on the combination of those hydrocarbons. Correcting for the background (mud) hydrocarbons can be done, as shown in FIG. 7, by taking mud samples from within the drill pipe (before the mud exits the drill bit and gets mixed with the formation fluid) and analyzing its hydrocarbon constituents and subtracting that value from the sum. The drill collar has an inner passageway 444 that is used to pump the mud into the bottom of borehole. Once the mud reaches the drill bit, it is directed out of the drill bit and into the well. Thus, the mud has a downward flow direction 445 inside the drill collar 446 and an upward direction 447 in the annulus 448. To take a sample of the incoming mud, a tube 442 may be connected between the inner passageway 444 of drill collar 446 and sample chamber 418.

In another embodiment, when water samples may be required, a water-wet porous plate may be used in cartridge 428 to allow only water to pass and be sampled. Similarly, when solids such as cuttings of a certain size are desired, a mesh of proper size may be used to separate the desired solids for further analysis.

Once the liquid or gas hydrocarbon of the sample is separated from the mud, it is possible to perform measurements on the sample at a downhole location. Particular techniques for performing those measurements are described, for example, in U.S. Pat. No. 7,458,257. In one embodiment, a quadrupole mass spectrometer (QMS) is used to measure the constituents of sample. The QMS measurement begins by ionizing the sample molecules using one of various methods (e.g., electron impact). The ions thus formed enter an evacuated chamber and pass through a quadrupole filter before reaching a detector. The detector outputs a signal that is proportional to the number of ions (i.e., concentration) that have passed through the quadrupole filter and struck the detector plate. The filter is made of four bars that are electrically charged to form the quadrupole. The bars are excited with a combination of DC and AC electric potentials, the interplay of which can be used to allow ions having particular mass-to-charge ratios to pass while blocking (filtering out) the remaining sample constituents. Thus, the filter may be sequentially tuned for different molecular masses and an intensity measured for each mass. The resulting mass spectrum provides information on the composition and the concentration of masses of the particular components originally present in the sample and also any fragments generated when those ions break down into smaller fragments. This information is combined to obtain the sample composition and the concentration of the different species. Measuring hydrocarbon composition is not limited to QMS. For example, different forms of chromatography may be used to separate individual components of the hydrocarbon mixture and measure their concentration. In yet another embodiment, spectroscopic methods such as UV-visible absorption spectroscopy, Raman spectrometry, infrared spectrometry, or Fourier transform infrared spectrometry (FTIR) can be used to analyze the composition and concentration of components in the sample.

Downhole measurements of sample properties (e.g., resistivity, nuclear, optical, nuclear magnetic resonance, sonic, etc.) allow a logging operator to obtain results in real-time. Those real-time results may be used to make drilling-related decisions. As stated above, those results are likely more accurate than results obtained at the surface if the sample properties would have been subject to temperature and pressure changes. It is well known in the art that at ambient (uphole) temperatures the solubility of larger constituents of crude oil (such as asphaltene) is reduced, causing them to precipitate out of the crude mixture and thereby making it difficult to quantify their concentrations. However, it may, at times, be desirable to analyze the sample uphole. In that case, the sample may be transported uphole without the loss of its composition or depth information to preserve measurement accuracy. In one such embodiment, a sample is extracted from the mud as described above and the sample is placed into a container (capsule) which is then released into the borehole annulus. While the mud pump is on, the upward flow 447 of mud in the annulus serves to carry the capsule to the surface where it can be collected (e.g., as the mud is passed over the shale shaker). The still “live” sample can then be analyzed at the surface.

Such capsules have been used to transport selected chemicals from uphole to downhole without the chemical being mixed into or diluted by the large volume of mud usually circulated into and out of the well. (See, for example, U.S. Pat. No. 7,063,163, U.S. Pat. No. 7,204,312, and WO 01/03676.) To pass a capsule from downhole to uphole, it is recommended that the capsule be a relatively small sample holder that can travel up the borehole in the space (annulus) between the drill collar and the borehole wall. As such there is a size limitation for usable capsules. For example, as FIG. 8 shows, when the diameter of the borehole 452 being drilled is eight inches and the drill pipe diameter 454 is six inches, there is a maximum two inch clearance in the annulus. If the drill pipe is concentric with the borehole, there will be a gap 456 of one inch all around the drill pipe and only a less than one inch capsule 458 can pass through. On the opposite extreme, when the drill pipe is eccentrically touching one side of the wellbore wall (FIG. 9), there is no clearance on the touching side, but there is a two inch clearance on the opposite side. As the mud flows, it will redirect itself to the two inch gap and, since it carries the capsule 458, it can transport capsules 458 of up to two inches in diameter. Note that the eccentricity is not constant along the length of the well and a capsule of close to two inch diameter will most likely be caught up or delayed at some depth. However, a capsule of one inch diameter has a very good chance of passing through the annulus independent of eccentricity. This example serves to demonstrate that a wide range of capsules 458 can be used depending on the diameter of borehole, the diameter of the drill pipe, and the eccentricity of the drill pipe relative to the borehole wall. For any combination of those parameters, the capsule having a diameter smaller than half the difference between the inner diameter of the wellbore and outer diameter of the drill pipe is optimum.

In some cases it is conceivable that the capsule 458 will be crushed by the rotary motion of the drill string. To cope with this possibility, multiple capsules may be charged with the same sample material and released to the annulus to increase the probability of at least one capsule 458 reaching the surface. Having multiple capsules 458 also helps offset the possibility that some capsules 458 are not detected and picked up at the shale shaker.

A capsule 460 is shown in FIG. 10 and has a wall 461 to contain the sample. The wall may be made of a material that is semi-flexible. Rubber or other flexible materials are examples of what may be used for this purpose. A capsule 460 made of flexible material can better survive when it is caught between the drill collar 446 and the borehole wall. Alternatively, the capsule 460 can be made of a material that is less flexible, but strong enough to absorb the mechanical strike without breaking apart. These materials can be metallic or fibrous, such as titanium, PEEK, or fiberglass.

The capsule 460 carries depth information and other information with it. The other information may be temperature, pressure, time, or even formation properties such as parameters measured by the LWD tools, including resistivity tools, nuclear tools, sonic tools, nuclear magnetic tools, etc. In a half-inch diameter capsule, for example, there is ample space to insert a small memory chip 462 and program it with the desired information before releasing it into the annulus. The chip may be built into the empty capsule beforehand and a microprocessor 472 in the BHA can transfer the information to the memory chip before it is released.

Once the capsules are in the shale shaker, the task is to find and collect them. For metallic capsules this can be done by subjecting the solids objects on the shale shaker to an electric field and detecting the resulting reflections off of the metal pieces. The electric field can be from electromagnetic radiation in the radio frequency (RF) range, for example. In another embodiment, a miniature antenna may be built into the structure of the capsule. This embodiment is very similar to what is known as RFID, and it allows the capsule to passively communicate with the RF source. To perform RFID on capsules, a metallic loop 464 may be imbedded in the structure of the capsule 460 making it possible to be detected by RF radiation. In another embodiment, shown in FIG. 11, the lower density of non-metallic or hollow metal capsules can be used to find and separate them. In this case, the cuttings 474 and capsules 460 and the mud 476 (or perhaps some other liquid) are introduced into a container. Usually the density of the mud and cuttings is higher than the capsules 460. This causes the capsules 460 to come to the top surface of the liquid 476 and be easily collected.

Introduction of the sample into the capsule (downhole charging) and extraction of sample from the capsule (uphole extracting) can be achieved using ports with a rubber seal 468, as shown in FIG. 10. This is similar to what is used in medical industry (penicillin samples, for example). In this approach, at least a section of the capsule body is made of thick rubber 468 (see FIG. 12) and the charging device is equipped with a needle 482 similar to a hypodermic needle used in the medical industry. In this embodiment the needle 482 is designed to operate while subjected to downhole environments (e.g., high pressures and temperatures). In operation, the needle 482 penetrates the rubber seal 468 and pump 484 injects the desired volume of sample into the capsule 460. Once this is done, the needle 482 is removed and the rubber adjusts itself to close and seal the hole just made by the insertion of needle 482. The extracting of the sample is done similarly with a needle 482 that is inserted into and through the rubber seal 468. The removed sample material can be directly connected to the uphole measuring instruments such as a mass spectrometer, a chromatography instrument, and the like. The type of measurements made on the sample uphole may include those that are standard in the industry. These include composition, density, and isotopic abundance of carbon-13, to name a few. In alternative embodiments, other ports that may be used for charging and extracting a sample include a valve that can be opened and closed while the capsule is attached to supporting framework for charging or extracting.

Attention is now directed to processing procedures, methods, techniques, and workflows that are in accordance with some embodiments. Some operations in the processing procedures, methods, techniques, and workflows disclosed herein may be combined and/or the order of some operations may be changed. It is important to recognize that geologic interpretations, sets of assumptions, and/or domain models such as velocity models may be refined in an iterative fashion. This concept is applicable to the processing procedures, methods, techniques, and workflows discussed herein. This iterative refinement can include use of feedback loops executed on an algorithmic basis, such as at a computing device (e.g., computing system 100, FIG. 3), and/or through manual control by a user who may make determinations regarding whether a given step, action, template, or model has become sufficiently accurate for the evaluation of the subsurface three-dimensional geologic formation under consideration.

As used herein, determining the petrophysical properties of a formation content may include, but is not limited to, the: (1) identification of productive hydrocarbon-bearing intervals, fluid types, and fluid contacts; (2) ability to identify and assess compartmentalization, both vertical and areal; (3) identification of bypassed/low-resistivity pay; (4) identification of changes in lithology; (5) ability to assess the effectiveness of reservoir seals; (6) identification of the charge history of an accumulation; (7) determining the thermal maturity of the hydrocarbon identified; and (8) geosteering using gas while drilling.

FIG. 13 shows a flowchart illustrating an embodiment in accordance with this disclosure. In this embodiment, the workflow comprises obtaining a sample comprising formation content from a subsurface formation and other sample constituents while the sample is in close proximity to the subsurface formation (1302); separating downhole the formation content from the other sample constituents (1304); analyzing downhole the formation content (1306); and determining petrophysical properties of the formation content (1308).

FIG. 14 shows a flowchart illustrating another embodiment in accordance with this disclosure. In this embodiment, the workflow comprises obtaining a sample comprising formation content from a subsurface formation, hydrocarbons from an oil based drilling fluid, and other sample constituents while the sample is in close proximity to the subsurface formation (1402); separating downhole the formation content and the oil based drilling fluid hydrocarbons from the other sample constituents (1404); analyzing the intermixed formation content and the oil based drilling fluid hydrocarbons (1406); accounting for the presence of the oil based drilling fluid hydrocarbons (1408); and determining petrophysical properties of the formation content (1410).

FIG. 15 shows a flowchart illustrating another embodiment in accordance with this disclosure. In this embodiment, the workflow comprises obtaining a sample comprising formation content from a subsurface formation and other sample constituents while the sample is in close proximity to the subsurface formation (1502); separating downhole the formation content from the other sample constituents (1504); charging one or more capsules with the formation content (1506); conveying the one or more capsules uphole (1508); analyzing uphole the formation content (1510); and determining petrophysical properties of the formation content (1512).

The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the scope of the present disclosure, and that they may make various changes, substitutions, and alterations herein without departing from the scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

While only certain embodiments have been set forth, alternatives and modifications will be apparent from the above description to those skilled in the art. These and other alternatives are considered equivalents and within the scope of this disclosure and the appended claims. Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 

What is claimed is:
 1. A method, comprising: obtaining a sample comprising formation content from a subsurface formation and other sample constituents while the sample is in close proximity to the subsurface formation; separating downhole the formation content from the other sample constituents by at least passing the sample through an oil-wet porous plate, a water-wet porous plate, or through both the oil-wet porous plate and the water-wet porous plate; analyzing downhole the formation content; and determining petrophysical properties of the formation content.
 2. The method of claim 1, wherein the separating downhole the formation content further comprises one or more of: passing the sample through a mesh, passing the sample into an expansion chamber, and drawing the sample into a chamber using a moveable piston.
 3. The method of claim 1, wherein the analyzing downhole the formation content comprises using one or more devices selected from the group consisting of: a mass spectrometer, a Raman spectrometer, an infrared spectrometer, an ultraviolet or visible light absorption spectrometer, a Fourier transform spectrometer operating in conjunction with any of the above-listed devices, and a chromatograph.
 4. The method of claim 1, wherein the determining petrophysical properties of the formation content comprises determining one or more of: hydrocarbon composition; hydrocarbon quantity; hydrocarbon ratios; identification of productive hydrocarbon-bearing intervals, fluid types, and fluid contacts; ability to identify and assess compartmentalization, both vertical and areal; identification of bypassed/low-resistivity pay; identification of changes in lithology; ability to assess the effectiveness of reservoir seals; identification of the charge history of an accumulation; determining the thermal maturity of the hydrocarbon identified; and geosteering using gas while drilling.
 5. A method, comprising: obtaining a sample comprising formation content from a subsurface formation, hydrocarbons from an oil based drilling fluid, and other sample constituents while the sample is in close proximity to the subsurface formation; separating downhole the formation content and the oil based drilling fluid hydrocarbons from the other sample constituents by at least passing the sample through an oil-wet porous plate, a water-wet porous plate, or through both the oil-wet porous plate and the water-wet porous plate; analyzing the intermixed formation content and the oil based drilling fluid hydrocarbons; accounting for the presence of the oil based drilling fluid hydrocarbons; and determining petrophysical properties of the formation content.
 6. The method of claim 5, wherein the separating downhole the formation content further comprises one or more of: passing the sample through a mesh, passing the sample into an expansion chamber, and drawing the sample into a chamber using a moveable piston.
 7. The method of claim 5, wherein the analyzing downhole the formation content comprises using one or more devices selected from the group consisting of: a mass spectrometer, a Raman spectrometer, an infrared spectrometer, an ultraviolet or visible light absorption spectrometer, a Fourier transform spectrometer operating in conjunction with any of the above-listed devices, and a chromatograph.
 8. The method of claim 5, wherein the determining petrophysical properties of the formation content comprises determining one or more of: hydrocarbon composition; hydrocarbon quantity; hydrocarbon ratios; identification of productive hydrocarbon-bearing intervals, fluid types, and fluid contacts; ability to identify and assess compartmentalization, both vertical and areal; identification of bypassed/low-resistivity pay; identification of changes in lithology; ability to assess the effectiveness of reservoir seals; identification of the charge history of an accumulation; determining the thermal maturity of the hydrocarbon identified; and geosteering using gas while drilling.
 9. The method of claim 5, wherein the accounting for the presence of the oil based drilling fluid hydrocarbons comprises analyzing substantially uncontaminated oil based drilling fluid for its hydrocarbon content and subtracting a corresponding hydrocarbon contribution from the results obtained from analyzing the intermixed formation content and the oil based drilling fluid hydrocarbons.
 10. A method, comprising: obtaining a sample comprising formation content from a subsurface formation and other sample constituents while the sample is in close proximity to the subsurface formation; separating downhole the formation content from the other sample constituents by at least passing the sample through an oil-wet porous plate, a water-wet porous plate, or through both the oil-wet porous plate and the water-wet porous plate; charging one or more capsules with the formation content; conveying the one or more capsules uphole; analyzing uphole the formation content; and determining petrophysical properties of the formation content.
 11. The method of claim 10, wherein the charging one or more capsules with the formation content comprises, for each capsule, injecting the formation content into the capsule through a self-sealing membrane and recording within a capsule memory at least depth information corresponding to the obtained sample.
 12. The method of claim 10, wherein the conveying the one or more capsules uphole comprises placing the one or more capsules into the wellbore annulus and using drilling fluid to transport the one or more capsules uphole.
 13. The method of claim 10, further comprising detecting uphole the one or more capsules using electromagnetic radiation, a liquid of density different from the one or more capsules, or a combination of those.
 14. An apparatus, comprising: a downhole tool disposed in a wellbore, the downhole tool having: a first sampling chamber in fluid communication with an annular region of the wellbore; a cartridge in fluid communication with the first sampling chamber; wherein a selective fluid barrier is disposed in the cartridge; and one or more downhole instruments to make one or more downhole measurements on a sample.
 15. The apparatus of claim 14, wherein the selective fluid barrier is selected from a group consisting of an oil-wet porous plate, a water-wet porous plate, and a back-to-back combination of oil-wet and water-wet porous plates.
 16. The apparatus of claim 14, further comprising a second sampling chamber, wherein the second sampling chamber comprises: a piston disposed in an interior region of the second sampling chamber; and a motor operatively joined to the piston.
 17. The apparatus of claim 14, wherein the first sampling chamber is selectively in fluid communication with an interior region of a drill pipe and the fluid communication between the first sampling chamber and the annular region of the wellbore is selective.
 18. An apparatus, comprising: a downhole tool having a sampler, the downhole tool being disposed in a wellbore having fluid therein and the sampler having a selective barrier through which a sample passes; and one or more capsules carried by the downhole tool, each of the one or more capsules being capable of containing a particular sample produced by the sampler and being releasable into the fluid in the wellbore.
 19. The apparatus of claim 18, wherein the sampler comprises: a first sampling tube in fluid communication with an annular region of the wellbore; and a separator in fluid communication with the first sampling tube.
 20. The apparatus of claim 19, wherein the separator comprises: a first sampling chamber having a first valve to allow or prevent fluid communication between the first sampling chamber and the first sampling tube; a fluid passageway joining the first sampling chamber to a second sampling chamber and having a second valve to allow or prevent fluid communication between the first sampling chamber and the second sampling chamber; and wherein the selective barrier is disposed in the fluid passageway.
 21. The apparatus of claim 20, wherein the selective barrier is selected from a group consisting of an oil-wet porous plate, a water-wet porous plate, and a back-to-back combination of oil-wet and water-wet porous plates.
 22. The apparatus of claim 20, wherein the separator further comprises: a piston disposed in an interior region of the second sampling chamber; and a motor operatively joined to the piston.
 23. The apparatus of claim 18, wherein each of the one or more capsules has an antenna.
 24. The apparatus of claim 18, wherein each of the one or more capsules has a self-sealing membrane through which the particular sample may be injected into an interior region of the capsule.
 25. The apparatus of claim 18, wherein each of the one or more capsules has a memory device. 